Search Results (36)

The development of shale bedding and fractures exacerbates the invasion of drilling fluid, leading to significant reservoir damage. This article elucidates the strength degradation behavior of shale with bedding orientations of 0° and 90° under drilling fluid immersion, as determined through triaxial compression experiments. An improved Hooke–Brown anisotropic strength criterion has been established to quantitatively characterize the degradation effects. Additionally, a dynamic mechanism of pore pressure accumulation was simulated. The research findings indicate the following: (1) As the intrusion pressure increases from 6 MPa to 8 MPa, the penetration depth significantly increases. In the horizontal bedding direction (0°), cracks dominate the flow mode, resulting in a sudden drop in strength; (2) An increase in bedding density or opening exacerbates the degree of invasion and strength degradation in the horizontal bedding direction, with a degradation rate exceeding 40%. In contrast, the vertical bedding direction is influenced by permeability anisotropy and crack blockage, leading to limited seepage and minimal degradation. By optimizing the dosage of emulsifiers and other treatment agents through orthogonal experiments, a low-viscosity, high-shear-strength plugging oil-based drilling fluid system was developed, effectively reducing the invasion depth of the drilling fluid by over 30%. The primary innovations of this article include the establishment of a quantitative model for Reynolds number degradation for the first time, which elucidates the mechanism of accelerated crack propagation during turbulent transition (when the Reynolds number exceeds the critical value of 10). Additionally, a novel method for synergistic control between sealing and rheology is introduced, significantly decreasing the degradation rate of horizontal bedding. Furthermore, the development of the Darcy–Forchheimer partitioning algorithm addresses the issue of prediction bias exceeding 15% in high-Reynolds-number regions (Re > 30). The research findings provide a crucial theoretical foundation and data support for the optimized design of drilling fluids. Full article

In well drilling operations, interactions between drilling fluid water-based and the well-bore present significant challenges, often escalating project costs and timelines. Particularly, fractures (both induced and natural) and permeable zones at the wellbore can result in substantial mud loss or increased filtration. Addressing these challenges, our research introduces a novel coupled numerical model designed to precisely calculate fluid losses in fractured and permeable zones. For the permeable zone, fundamental variables such as filtration velocity, filtrate concentration variations, permeability reduction, and fluid cake growth are calculated, all based on the law of continuity and convection-dispersion theory. For the fracture zone, the fluid velocity profile is determined using the momentum balance equation and both Newtonian and non-Newtonian rheology. The model was validated against laboratory data and physical models, and adapted for field applications. Our findings emphasize that factors like mud particle size, shear stress, and pressure differential are pivotal. Effectively managing these factors can significantly reduce fluid loss and mitigate formation damage caused by fluid invasion. Furthermore, the understanding gathered from studying mud behavior in both permeable and fractured zones equips drilling personnel with valuable information related to the optimal rheological properties according to field conditions. This knowledge is crucial for optimizing mud formulations and strategies, ultimately aiding in the reduction of non-productive time (NPT) associated with wellbore stability issues. Full article

The instability of wellbore in hard and brittle shale formations is a key bottleneck constraining the safety and efficiency of drilling engineering. Traditional studies focused on drilling fluid density, particle plugging, and chemical inhibition; however, there is a lack of in-depth analysis on the precise control mechanism of wellbore stability by the rheological properties of drilling fluids. Specifically, while traditional methods are limited in addressing mechanical instability in hard brittle shales with pre-existing micro-fractures, rheological control offers a potential solution by influencing pressure transmission within these fractures. To address this research gap, this study aims to reveal the influence of drilling fluid rheological parameters (specifically viscosity and yield point) on the pressure transmission behavior of the micro-fracture network in hard and brittle shale and to clarify the intrinsic mechanism by which rheological properties stabilize the wellbore. Micro-structure analysis confirmed interconnected micro-fractures (0.5–30 μm). A micro-fracture flow model and simulations evaluated viscosity and yield point effects on pressure transmission. A higher viscosity significantly increased the pressure drop (ΔP) near the wellbore, with limited transmission distance effects. The yield point was minimal. The study reveals that optimizing rheology, particularly increasing viscosity, can suppress pore pressure, reduce collapse pressure, and improve stability. The findings support rheological parameter optimization for safer, economical drilling. In terms of rheological parameter optimization design, this study suggests emphasizing the increase in drilling fluid viscosity to effectively manage wellbore stability in hard brittle shale formations. Full article

Uniform acid distribution is a critical challenge and a key factor for the successful acidizing of carbonate reservoirs. Previous experimental studies have shown that nanoparticles can enhance the viscosity and thermal resistance of viscoelastic surfactant (VES) fracturing fluids. However, there has been limited research on the effects of nanoparticles on the wormhole propagation and diversion performance of VES acid. This paper establishes a nanoparticle VES acid rheological model based on rheology experiments, and introduces a porous medium temperature field and nanoparticle adsorption model into a two-scale continuum model to establish a mathematical model for the expansion of wormholes in nanoparticle VES acid. The accuracy of the wormhole model is verified through laboratory experiments. The effects of permeability contrast, initial acid temperature, and nanoparticle adsorption on the diversion performance and wormhole propagation of nanoparticle VES acid are analyzed. The results indicate that nanoparticle VES acid differs from conventional VES acid, with its invaded zone divided into high-viscosity and low-viscosity zones. The presence of the high-viscosity zone allows nanoparticle VES acid to improve wormhole propagation in low-permeability cores by 16.2% compared to conventional VES acid. At 393 K, nanoparticle VES acid has a better diversion effect in carbonate cores with permeability contrast of 10, as the acid fluid flows faster in high-permeability cores, resulting in wormhole shapes with more branches. Numerical model results show that when the permeability contrast is 8, increasing the injection temperature of the acid solution from 293 K to 368 K improves the ability of low-permeability cores by 33.3%. This study establishes a mathematical model for nanoparticle VES acid based on laboratory experiments and numerical simulations, investigates the effects of nanoparticles on VES rheological properties under acidic conditions, and clarifies the wormhole propagation and acid diversion behavior of nanoparticle VES acid, providing guidance for future field applications of this acid. Full article

Hydraulic fracture stimulation is one of the most effective methods to recover oil and gas from unconventional resources. In recent years, foam-based fracturing fluids have been increasingly studied to address the limitations of conventional slickwater such as high water and chemical consumption, environmental concerns, and high incompatibility with water-sensitive formations. Due to the gradual breakdown of liquid foams at reservoir conditions, the combination of silica nanoparticles (SNP) and surfactants has attracted a lot of attention to improve liquid foams’ characteristics, including their stability, rheology, and proppant-carrying capacity. This paper investigates and compares the effects of cationic and anionic surfactants on the fracturing performance of SNP-stabilized foams at the reservoir temperature of 90 °C. The experimental results of viscosity measurements were imported into a 3D fracture-propagation model to evaluate the effectiveness of fracturing foams in transporting and distributing proppants in the fracture system. At both ambient and elevated temperatures, cationic surfactant was experimentally found to have better synergistic effects with SNP than anionic surfactant in improving the apparent viscosity and proppant-carrying capacity of foams. The simulation results demonstrate that fracturing with cationic surfactant-SNP foam delivers greater performance with larger propped area by 4%, higher fracture conductivity by 9%, and higher cumulative gas production by 13%, compared to the anionic surfactant-SNP foam. This research work not only helps validate the interrelationship between fluid viscosity, proppant settlement rate, and fracture effectiveness, but it also emphasizes the importance of proppant placement in enhancing fracture conductivity and well productivity. Full article

Improving the chemical structure of the cross-linker is a potential method for reducing reservoir pollution and enhancing the fracturing efficiency of shale reservoirs. In this investigation, a three-dimensional (3-D) spherical cross-linker comprising branched chains was synthesized, and the 3-D structure of the cross-linker was analyzed through scanning electron microscopy (SEM). Furthermore, we constructed a multifunctional coupled collaborative evaluation device that can be used to evaluate numerous properties associated with water-based fracturing fluids, including fluid viscosity, adsorption capacity, and water pollution. Meanwhile, the influence of varying reservoir conditions and cross-linker content on the fluid viscosity of water-based fracturing fluids and the potential for reservoir contamination has been evaluated and elucidated. The results indicated that the synthesized cross-linker exhibited a superior environmental protection of the shale reservoir and an enhanced capacity for thickening fracturing fluids in comparison to commercial cross-linkers. Moreover, cross-linker content, reservoir temperature, reservoir pressure, and fracture width can affect fluid viscosity and reservoir residual in different trends. The addition of 0.3% nano-cross-linker (Synthetic products) to a water-based fracturing fluid resulted in an apparent viscosity of 160 mPa·s at 200 °C, and the adsorption capacity and water content of the shale reservoir were only 0.22 µg/m³ and 0.05 µg/L, respectively. Additionally, an elevation in reservoir temperature resulted in a reduction in the adsorption capacity. However, the cross-linker content in groundwater underwent a notable increase, and the cross-linker residue in water increased by 0.009 µg/L. The impact of reservoir pressure on fluid viscosity and groundwater pollution potential exhibited an inverse correlation compared to that of reservoir temperature, and the above two parameters changed by +18 mPa·s and −0.012 µg/L, respectively. This investigation provides basic data support for the efficient fracturing and reservoir protection of shale reservoirs. Full article

Water-based fracturing fluid has recently garnered increasing attention as an alternative oilfield working fluid for propagating reservoir fractures and transporting sand. However, the low temperature resistance and stability of water-based fracturing fluid is a significant limitation, restricting the fracture propagation and gravel transport. To effectively ameliorate the temperature resistance and sand-carrying capacity, a modified cross-linker with properties adaptable to varying reservoir conditions and functional groups was synthesized and chemically characterized. Meanwhile, a multifunctional collaborative progressive evaluation device was developed to investigate the rheology and sand-carrying capacity of fracturing fluid. Utilizing molecular dynamics simulations, the thickening mechanism of the modified cross-linker and the sand-carrying mechanism of the fracturing fluid were elucidated. Results indicate that the designed cross-linker provided a high viscosity stability of 130 mPa·s and an excellent sand-carrying capacity of 15 cm² at 0.3 wt% cross-linker content. Additionally, increasing reservoir pressure exhibited enhanced thickening and sand-carrying capacities. However, a significant inverse relationship was observed between reservoir temperature and sand-carrying capacity, attributed to changes in the drag coefficient and thickener adsorption. These results verified the effectiveness of the cross-linker in enhancing fluid viscosity and sand-carrying capacity as a modified cross-linker for water-based fracturing fluid. Full article

Thermosetting resins have good temperature resistance and high strength and have been widely used as plugging agents in oil fields. However, the current resin materials have high costs, and unmodified thermosetting resins are brittle or have deteriorated properties such as flame retardancy after curing to form a crosslinked network structure. In this study, the resin was modified via physical blending. The curing strength and temperature resistance were used as the main indicators. The resin matrix, curing agent, rheology modifier, and filling materials were modified and formulated optimally to form a high-strength resin gel plugging system. The resin gel system exhibited good fluidity and pumpability. When the shear rate was 200 s⁻¹ at 25 °C, the initial viscosity was 300–400 mPa·s. The viscosity gradually decreased with increasing shear rate, and the apparent viscosity had good long-term stability at room temperature. A contamination test of different types of drilling fluids on the resin gel system showed that this system had good anti-contamination capability and could maintain a high curing strength even after being contaminated. At the same time, the system exhibited good plugging capability. A wedge-shaped fracture with an inlet size of 7 mm and an outlet size of 5 mm was plugged at 12.84 MPa for 10 min without leakage. A sand-filling pipe (with a diameter of 3.8 cm and pipe length of 30 cm) connected to the pipeline with a 6 mm outlet was subjected to a constant pressure of 11.29 MPa and plugged for 8 min before breaking through. Therefore, it exhibited good capability for plugging fissures and cavities. The resin gel leakage-plugging system has significant potential to realize effective plugging of the deep large-fracture leakage layer. Full article

Nanomaterials play a beneficial role in enhancing the rheological behavior of fracturing (frac) fluid by reacting with intermolecular structures. The inclusion of these materials into the fluid improves its stability, increases the viscosity of polymers, and enhances its resistance to high temperature and pressure. In this investigation, multi-walled carbon nanotubes (CNTs), nano-zinc oxides (N-ZnO), and nano-copper oxides (N-CuO) have been utilized to ameliorate the rheological properties of water-based fracturing fluid. Different concentrations of these aforementioned nanomaterials were prepared to determine their effects on the rheological behavior of the fluid. The results revealed that the size of nanoparticles ranged from 10 to 500 nm, 300 nm, and 295 nm for CNTs, N-ZnO, and N-CuO, respectively. Moreover, employing CNTs exhibited a resistance of 550 cp at 25 °C and reached 360 cp at 50 °C with a CNT concentration of 0.5 g/L. In contrast, N-CuO and N-ZnO showed a resistance of 206 cp at 25 °C and significantly decreased to 17 cp and 16 cp with higher concentrations of 10 g/L and 1 g/L, respectively. Based on these findings, this study recommends utilizing CNTs to enhance fracking fluid’s chemical and physical properties, which need to be highly viscous and stable under reservoir conditions. Full article

Viscous slickwater has a higher viscosity and better sand-carrying ability than conventional slickwater at the same concentration. At a concentration of 0.4 wt.%, the viscosity of the viscous slickwater is 4.7 times that of the conventional slickwater. It is generally believed that viscosity is one of the main influencing factors on the sand-carrying ability of the fluid. However, this study has shown that the good sand-carrying ability of the viscous slickwater is more attributed to its viscoelasticity. Through rheology and sand-carrying tests, it has been found that the viscoelastic properties vary when fluids have the same viscosity; this then leads to a significant difference in the settling rate of sand and the sand-carrying threshold of the fluid in a fracture at a certain flow rate. The routine method of characterizing the viscoelastic property of the slickwater was to observe the cross point of the elastic modulus (G′) and viscous modulus (G″) curves. The smaller the frequency of the cross point, the better the viscoelastic property of the fluid. However, it has been found in experiments that even when the cross point is the same, there is still a significant difference in the sand-carrying ability of fluids. Therefore, sand-carrying experiments are conducted under a similar cross point and different magnitudes of modulus, of which the results indicate that as the elastic modulus increases, the settling rate of sand decreases. The flow rate threshold occurring as sand settles obtained from laboratory experiments is compared with the field condition during hydraulic fracturing. From laboratory experiments, the threshold of inner-fracture flow rate that prevents the sand settling is found to be 8.02 m/min for 0.6 wt.% viscous slickwater with a sand ratio of 30%. In the field operation, the operation conditions meet the sand-carrying threshold obtained from laboratory experiments. Observations from the field test confirm the applicability of the threshold plot proposed according to laboratory measurements, which can provide guidance for optimizing the fracturing scheme in the field. Full article

In the last decade, hydrogels for hydraulic fracturing based on viscoelastic surfactants have been actively studied. Interest in these systems is justified by their unique qualities: good viscoelasticity and the ability to form stable suspensions of proppant or sand, destruction without the formation of bridging agents, hydrophobization of the rock surface and metal of technological equipment, as well as oil-cleaning properties. These qualities are most often provided by a minimum set of components—a surfactant and an electrolyte. However, the absence of a polymer limits the use of these gels in formations where fluid leakoff is possible. In this article, a liquid was studied, based on a pseudo gemini surfactant (PGVES) with the addition of a water-soluble polysaccharide. The objects of study were selected based on the assumption of interactions between PGVES and the polymer; interactions which favorably influence the technological characteristics of the fracturing fluid. To confirm the hypothesis, rheological studies were carried out. These included rotational viscometry and oscillatory studies at various temperatures. The settling velocity of particles of various proppant fractions was studied and tests were carried out to assess fluid leakoff. The performed experiments show an improvement in the characteristics of the PGVES-based gel under the influence of the polysaccharide. In particular, the rheological properties increase significantly, the stability of proppant suspensions improves, and the fluid leakoff of systems decreases, all of which expands the possibility of using these fracturing fluids and makes this area of experimentation promising. Full article

This research delves into the complexities of backflow phenomena in finite-length and flat-walled fractures with elastic walls, specifically focusing on power-law fluids, whose shear-thinning behavior distinguishes them from Newtonian fluids. We model the backflow process under the lubrication approximation and by incorporating the linear Navier slip law. We numerically examine the influence of parameters such as slip length, fluid rheology, and external pressure on the backflow propagation of the carrier fluid. Our findings underscore the significant role played by the rheological index in determining the fracture closure rate. Additionally, our investigations highlight the marked effect of external pressure variations on pressure distribution within the fracture. Notably, the friction coefficient at the fracture walls, as denoted by a dimensionless slip number, exhibits limited influence on the fundamental dynamics of the problem. These insights advance our understanding of power-law fluid backflow and have wide-ranging applications across various engineering disciplines. Full article

The fractured granite reservoir is well developed in Yongle block, which leads to severe drilling fluid loss-circulation. To solve the technical problem of both plugging and reservoir protection, on the basis of comprehensive literature research and laboratory tests at home and abroad, a polymer with an appropriate molecular weight, an organic crosslinking agent and other auxiliary materials were screened. In addition, a kind of high-temperature resistant loss-circulation plugging gel, which could be formed by timing and self-degradation, was developed. The high-strength gel loss-circulation system can be established by the development of a dynamic covalent borate ester bond crosslinking agent, which can crosslink with polyvinyl alcohol and xanthan gum. This system is of formidable strength and can be used for loss-circulation control in a fractured formation. The dynamic covalent borate ester bond tends to break due to the peroxide glue breaker under low pH levels, which can accelerate the degradation of the plugging gel into small molecules. The degradable temporary plugging material can ensure high-performance sealing and self-degradation capabilities of the fractured granite reservoir. The laboratory results showed that the high-performance degradable gel system was of adjustable gelling time, high gelling strength and high sealing capability. Its pressure-bearing could reach 5.8 MPa under 110 °C with 3.5 mm width of fractured granite core. Before crosslinking, the system also boasted promising thixotropy and rheology. The gel breaking time of the system was short, which could be completely broken with 6.1 h in 6% peroxide solution with pH of 4. The gelation time was related to the type of crosslinking agent, the amount of crosslinking agent and temperature. With the increase of temperature, the gelation time of gel system decreased. With the increase of the amount of the agent, the gelation time of gel system decreased. The gelation time was 105 min when using a 1% dynamic covalent borate ester bond crosslinking agent at 80 °C; the gelation time was 72 min when using a 1% dynamic covalent borate ester bond crosslinking agent at 110 °C; the gelation time was 71 min when using a 2% dynamic covalent borate ester bond crosslinking agent at 80 °C; the gelation time was 65 min when using a 2% dynamic covalent borate ester bond crosslinking agent at 110 °C; the gelation time was 72 min when using a 1% chromium crosslinking agent at 80 °C; the gelation time was 63 min when using a 2% chromium crosslinking agent at 80 °C; and the gel system had good reservoir protection performance. The permeability recovery rate was introduced to evaluate reservoir protection performance. The permeability recovery rate of using the dynamic covalent borate ester bond crosslinking agent was superior to that of using the chromium crosslinking agent. Using the dynamic covalent borate ester bond crosslinking agent, when the fracture width was 1.6 mm, the temperature was 80 °C and the soaking time was 8 h, the permeability recovery rate was 90.32%; when the fracture width was 0.75 mm, the temperature was 80 °C and the soaking time was 8 h, the permeability recovery rate was 84.53%. Using the chromium crosslinking agent, when the fracture width was 1.6 mm, the temperature was 80 °C and the soaking time was 12 h, the permeability recovery rate was 59.58%; when the fracture width was 0.75 mm, the temperature was 80 °C and the soaking time was 12 h, the permeability recovery rate was 45.65%. The viscosity of the residual solution was low and was helpful for reservoir protection during loss-circulation control under the fractured granite reservoir condition. The novel degradable temporary plugging material can solve the loss-circulation problem of the ultra-deepwater fractured granite reservoir. In addition, the material can pave the way for the exploration and development of a vast amount of hydrocarbon resources in the South China Sea. Full article

Surfactant-based viscoelastic (SBVE) fluids have recently gained interest from many oil industry researchers due to their polymer-like viscoelastic behaviour and ability to mitigate problems of polymeric fluids by replacing them during various operations. This study investigates an alternative SBVE fluid system for hydraulic fracturing with comparable rheological characteristics to conventional polymeric guar gum fluid. In this study, low and high surfactant concentration SBVE fluid and nanofluid systems were synthesized, optimized, and compared. Cetyltrimethylammonium bromide and counterion inorganic sodium nitrate salt, with and without 1 wt% ZnO nano-dispersion additives, were used; these are entangled wormlike micellar solutions of cationic surfactant. The fluids were divided into the categories of type 1, type 2, type 3, and type 4, and were optimized by comparing the rheological characteristics of different concentration fluids in each category at 25 °C. The authors have reported recently that ZnO NPs can improve the rheological characteristics of fluids with a low surfactant concentration of 0.1 M cetyltrimethylammonium bromide by proposing fluids and nanofluids of type 1 and type 2. In addition, conventional polymeric guar gum gel fluid is prepared in this study and analyzed for its rheological characteristics. The rheology of all SBVE fluids and the guar gum fluid was analyzed using a rotational rheometer at varying shear rate conditions from 0.1 to 500 s⁻¹ under 25 °C, 35 °C, 45 °C, 55 °C, 65 °C, and 75 °C temperature conditions. The comparative analysis section compares the rheology of the optimal SBVE fluids and nanofluids in each category to the rheology of polymeric guar gum fluid for the entire range of shear rates and temperature conditions. The type 3 optimum fluid with high surfactant concentration of 0.2 M cetyltrimethylammonium bromide and 1.2 M sodium nitrate was the best of all the optimum fluids and nanofluids. This fluid shows comparative rheology to guar gum fluid even at elevated shear rate and temperature conditions. The comparison of average viscosity values under a different group of shear rate conditions suggests that the overall optimum SBVE fluid prepared in this study is a potential nonpolymeric viscoelastic fluid candidate for hydraulic fracturing operation that could replace polymeric guar gum fluids. Full article

Quasi-dry CO₂ fracturing technology is a new CO₂ fracturing technology that combines liquid CO₂ fracturing (dry CO₂ fracturing) and water-based fracturing. It uses a liquid CO₂ system containing a small amount of water-based fracturing fluid to carry sand, and it is characterized by sand blending at normal pressure, convenient preparation, the integrated application of resistance reduction and sand carrying, and no dedicated closed sand blender requirement. We developed a self-crosslinking emulsion-type water-based fracturing fluid (ZJL-1), which contained ionic bonds, hydrogen bonds, van der Waals forces, and hydrophobic associations, for quasi-dry CO₂ fracturing, and the comprehensive properties of the ZJL-1 fracturing fluid were evaluated. The results showed that the ZJL-1 fracturing fluid had obvious viscoelastic characteristics, a heat loss rate of less than 10% at 200 °C, a good thermal stability, sufficient rheology under high temperature and high shear conditions, and a good thermal stability. The resistance reduction rate reached 70%, which demonstrates a good resistance reduction performance. Compared with conventional guar fracturing fluid, ZJL-1 can carry more sand and has a lower core damage rate. The on-site use of quasi-dry fracturing showed that optimizing the mixing ratio of liquid CO₂ fracturing fluid and ZJL-1 fracturing fluid effectively enhanced oil and gas recovery. This can be used to optimize quasi-dry fracturing and can be used as a reference. Full article